CONFIDENTIAL

Q3 2014 Investor Presentation

November 2014

Cautionary Note Regarding Forward-looking Statements

2

To the extent any statements made in this presentation contain information that is not historical, these statements are forward-looking statements or forward-looking information, as applicable, within the meaning of

Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended, and under Canadian securities law (collectively “forward-looking statements”).

Forward-looking statements can generally be identified by the use of words such as “should,” “intend,” “may,” “expect,” “believe,” “anticipate,” “estimate,” “continue,” “plan,” “project,” “will,” “could,” “would,” “target,”

“potential” and other similar expressions. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Although

Atlantic Power Corporation (“AT”, “Atlantic Power” or the “Company”) believes that the expectations reflected in such forward-looking statements are reasonable, such statements involve risks and uncertainties and

should not be read as guarantees of future performance or results, and undue reliance should not be placed on such statements. Please refer to the factors discussed under “Risk Factors” and “Forward-Looking

Information” in the Company’s periodic reports as filed with the Securities and Exchange Commission from time to time for a detailed discussion of the risks and uncertainties affecting the Company, including, without

limitation, the outcome or impact of the Company’s business plan, including the objective of enhancing the value of its existing assets through optimization investments and commercial activities, delevering its balance

sheet to improve its cost of capital and ability to compete for new investments, and utilizing its core competencies to create proprietary investment opportunities, and the Company’s ability to evaluate and/or

implement potential options, including asset sales or the contribution of assets to a joint venture in order to raise additional capital for growth and/or debt reduction, and the outcome or impact on the Company’s

business of any such potential options. Although the forward-looking statements contained in this presentation are based upon what are believed to be reasonable assumptions, investors cannot be assured that

actual results will be consistent with these forward-looking statements, and the differences may be material. These forward-looking statements are made as of the date of this presentation and, except as expressly

required by applicable law, the Company assumes no obligation to update or revise them to reflect new events or circumstances. The Company’s ability to achieve its longer-term goals, including those described in

this presentation, is based on significant assumptions relating to and including, among other things, the general conditions of the markets in which it operates, revenues, internal and external growth opportunities, its

ability to sell assets at favorable prices or at all and general financial market and interest rate conditions. The Company’s actual results may differ, possibly materially and adversely, from these goals.

Free Cash Flow, Cash Distributions from Projects and APLP Project Adjusted EBITDA are not measures recognized under GAAP and do not have standardized meanings prescribed by GAAP. Free Cash Flow is

defined as cash flows from operating activities less capex; project-level debt repayments, including amortization of the new term loan; and distributions to noncontrolling interests, including preferred share dividends.

Management believes that Free Cash Flow and Cash Distributions from Projects are relevant supplemental measures of the Company's ability to earn and distribute cash returns to investors. Reconciliations of Free

Cash Flow to cash flows from operating activities and of Cash Distributions from Projects to project income (loss) are provided on slide 45 of this presentation. Investors are cautioned that the Company may calculate

these measures in a manner that is different from other companies.

Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project

Adjusted EBITDA is not a measure recognized under GAAP and is therefore unlikely to be comparable to similar measures presented by other companies and does not have a standardized meaning prescribed by

GAAP. Management uses Project Adjusted EBITDA at the project level to provide comparative information about project performance and believes such information is helpful to investors. A reconciliation of Project

Adjusted EBITDA to project income (loss) and a bridge to Cash Distributions from Projects are provided on slide 45 of this presentation. Investors are cautioned that the Company may calculate this measure in a

manner that is different from other companies.

Adjusted EBITDA is defined as (i) for the Company’s consolidated projects: project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in the fair

value of derivative instruments, plus (ii) for the Company’s equity-method projects: cash distributions to the Company from these projects; less (iii) corporate administration expense as shown on the Company’s

consolidated statement of operations. Adjusted EBITDA is not a measure recognized under GAAP and is therefore unlikely to be comparable to similar measures presented by other companies and does not have a

standardized meaning prescribed by GAAP.

Adjusted EBITDA to Interest Coverage ratio is defined as Adjusted EBITDA divided by the sum of (ii) project-level interest expense, net, as shown on the Company’s consolidated statement of operations, and (ii)

corporate interest expense, net, as shown on the Company’s consolidated statement of operations.

The Company has not reconciled non-GAAP financial measures relating to individual projects or to the APLP projects to the directly comparable GAAP measures due to the difficulty in making the relevant adjustments

on an individual project basis. The Company has not provided a reconciliation of forward-looking non-GAAP measures, because not all of the information necessary for a quantitative reconciliation is available to the

Company without unreasonable efforts primarily as a result of the variability and difficulty in making accurate forecasts and projections.

All amounts in this presentation are in US$ and approximate unless otherwise stated.

Disclaimer – Non-GAAP Measures

Executive Summary:

The Right Path to Rebuild Shareholder Value

3

Executive Summary: The Right Path to Rebuild Shareholder Value

4

Executing on plan to drive long-term shareholder value

• Firm commitment to explore and pursue opportunities to create long-term value for

shareholders

Review of strategic options confirmed that it is in the Company’s best interest to remain independent

and execute on existing business plan

Continuing to evaluate asset sales and partnerships to realize maximum value for our assets

• On the right path to improve the Company’s financial position and enhance shareholder

returns

Focused capital allocation strategy:

o Attractive investments in existing businesses

o Debt reduction

Ensure cost structure is in line

Enhance or extend PPAs where economically attractive

Already seeing positive results

• Retained executive search firm to recruit permanent CEO

Executive Summary: Action Plan for Long-Term Shareholder Value

5

Executing on plan to drive long-term shareholder value

1. Invest in existing businesses

Continue to make optimization investments in existing fleet designed to improve efficiency, boost

output or reduce costs

Attractive expected returns (five-year payback or 20% current yield)

Targeting approximately $5 to $10 million of discretionary investment in 2015

Expect to fund out of Free Cash Flow

2. Reduce high-cost debt and improve credit metrics

Amortization of project and term loan debt from project-level cash flow

Reduction in leverage using proceeds from selective asset sales under consideration

Opportunistic market purchases of debt securities

Benefits:

Reduced financial risk

Lower cost of capital

Improved ability to compete for new investments

Executive Summary: Action Plan for Long-Term Shareholder Value

6

Executing on plan to drive long-term shareholder value

3. Cut overhead costs

Already taken aggressive actions to reduce corporate expenses in the areas of personnel,

development and administrative costs

Expected annual savings of at least $15 million in 2015 relative to 2013 (28% reduction)

Evaluating further potential cost reductions

4. Pursuing commercial opportunities to enhance value of our assets

Extend or renew PPAs where economically attractive

Expanding relationships with existing offtakers/customers to meet their needs for reliability

and efficiency while improving margins

• Balance sheet

Repaid $73 million project and APLP term loan debt year to date; on track for $85 million by year-end

Repaid Cdn$44.8 million convertible debenture at maturity using cash; now have no non-amortizing

corporate debt maturities prior to March 2017

Strong liquidity of $231 million, including $127 million of unrestricted cash (1)

• Cost structure

Implemented personnel and other cost reductions to achieve $15 million annual savings in corporate

G&A expense in 2015 relative to 2013 (28% reduction)

• Portfolio

2013-2014 planned optimization investments of $27 million largely completed and on track to produce

$8 million of annual cash flow (30% return)

• Year-to-date financial results

Still expect to achieve midpoint of Project Adjusted EBITDA guidance ($285 - $300 million)

Positive Free Cash Flow in Q3 and year to date (2)

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Executive Summary: Significant Progress in Key Areas

Executing on plan to drive long-term shareholder value

(1) Pro forma unrestricted cash reflects repayment of $41 million (Cdn$44.8 million) of convertible debentures (ATP.DB) on October 31, 2014 at maturity; (2) See slides 17 and 18 for calculation of Free Cash Flow (Adjusted).

.

Strategic and Financial Update

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• On track for $27 million of optimization investments in 2013 and 2014

- Investments in our existing projects with expected strong payback, more modest capital investment

and shorter lag to cash returns than typical construction projects

- Still expecting run-rate cash flow contribution of at least $8 million annually in 2015, equivalent to

~30% current yield

o At least $4 million of that already realized in 2014

• Major projects planned for this year now mostly completed:

- Curtis Palmer Unit 4 & 5 repowering (completed ahead of schedule)

- North Island capacity uprate (completed in March)

- Mamquam completed work to increase output by 4 MW

- Calstock boiler re-rate completed, increasing output by 2 MW

- Morris installation of PowerPhase technology completed in August

o Increases output by 7 MW during high temperatures

- Nipigon steam generator replacement and upgrade completed in August

o Improvement in efficiency and reliability to increase revenues

Focusing Our Capital Allocation Priorities: Optimization Investments

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• 2014 major maintenance and capex of approximately $35 million

- Routine major maintenance and capex of approximately $20 million

- Optimization initiatives of approximately $18 million, including $3 million included in operating

expense

• Preliminary 2015 budget of $30 to $35 million

- Routine major maintenance and capex of approximately $25 million

- Expect to make discretionary investments of approximately $5 to $10 million

Major Maintenance and Capex Update

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Expecting strong returns from discretionary investments

Focusing Our Capital Allocation Priorities: Deleveraging

11

• Targeting general credit profile with the following attributes to facilitate access to the

capital markets over time (1):

- Consolidated Debt to Adjusted EBITDA ratio in the range of 5.0-5.75x

- Consolidated Debt to Total Capitalization ratio of approximately 60%

- Adjusted EBITDA to Interest Coverage multiple of 2.5x or better

• Steps to achieve

- Amortize project debt and APLP term loan in the amount of $80 to $85 million annually

(average for 2015 – 2017)

o On track for $85 million reduction in debt by year-end 2014

- Significant reduction in leverage using proceeds from selective asset sales or joint ventures

currently under consideration

- Repurchase outstanding debt securities where economically attractive

o Implemented normal course issuer bid program for at least $15 million and up to 10% of outstanding

convertible debentures ($35 million)

• Expect $10 million annualized cash interest savings from Q1 debt redemption and

repurchase transactions and repayment of converts in October (2)

Goal is to achieve these credit metrics by year-end 2016

(1) See definitions of the terms listed below on slide 2 of this presentation; (2) See slide 36 for details on deleveraging activities in 2014.

Sharpening Our Cost Focus

Corporate G&A and Development Expense ($ millions)

12

2013 2014 Guidance

Reported $53.8 $44

(6)

Adjusted $38

Have already taken steps to achieve at least $15 million annual savings in 2015 relative to 2013

See slide 41 in Appendix for break-down of expenses between Unallocated Corporate and Corporate G&A.

Severance charges Q3 + Q4

Run-rate for 2015 based on cost reductions to date.

Actual level expected to be modestly lower.

Actions taken:

Q3 2013 $(8) Reduction in development and administrative expenses

Q3 2014 $(7) Personnel reductions, management changes and other initiatives

Project

Adjusted

EBITDA

Free

Cash

Flow (1)

Initial (2/27/14) $280 - $305 $0 - $25

Material changes:

Severance costs $(6)

Current (11/6/14) $285 - $300 $0 - $10

YTD September 30, 2014 $221.6 $9.1 (1) Free Cash Flow guidance excludes $49.4 million of debt repayment and repurchase costs and $8.1 million of Piedmont debt repayment at

term conversion, both recorded in Q1 2014.

2014 Guidance ($ millions)

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Midpoint of Project Adjusted EBITDA guidance

is unchanged

Reduction in Free Cash Flow guidance reflects

cash payments for severance in Q3 and Q4

Q3 2014 Operational and Financial Review

100531 14

Q3 2014 Highlights

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• Q3 operational and financial results generally in line with expectations

Improved availability (95% in Q3 vs. 92% in first half)

Lower generation due to mild summer and other factors

Modest decline in Project Adjusted EBITDA but full year tracking to guidance midpoint

Positive Free Cash Flow after negative first half

Now expecting 2014 Free Cash Flow of $0 to $10 million (1), in lower end of initial guidance range,

due to employee severance charges in Q3 and Q4 (~$6 million)

Repaid $14 million of project and term loan debt; on track for $85 million reduction in 2014

• Recent developments

Settlement of arbitration with Piedmont EPC contractor (Zachry)

Selkirk PPA expiration

Tunis project update

Retained executive search firm for permanent CEO

(1) 2014 Free Cash Flow guidance is net of planned capital expenditures totaling $16 million and debt repayments under the APLP term loan of an estimated $53 million in 2014 pursuant to the term loan’s mandatory amortization

and cash sweep.

Q3 and YTD 2014 Highlights – Project Adjusted EBITDA ($ millions)

16

Q3 – Modest decrease:

- Selkirk – lower dispatch (mild summer); PPA expiration

- Navy projects (CA) – lower energy revenues and higher

maintenance expense

- Sale of Delta-Person and Gregory

- Scheduled outages at Calstock and Chambers

- Lower water at Curtis Palmer

+ Ontario gas projects - higher waste heat, lower

maintenance expense

+ Orlando – favorable changes to PPA and gas costs

+ Canadian Hills – favorable winds

Project Adjusted EBITDA

2014 2013 Change

Q3 72.2 75.0 (2.8)

Q3 and YTD results are on track with midpoint of our 2014 guidance range

Note: Please see detail for Project Adjusted EBITDA results on slides 33 and 34.

YTD – Increase in line with expectations:

+ Ontario gas projects – higher waste heat, lower

maintenance expense

+ Wind projects – favorable winds

+ Morris – lower maintenance; higher merchant capacity and

ancillary services revenues

+ Un-allocated corporate – reduction in G&A and

development expense

+ Orlando – favorable changes to PPA and gas costs,

partially offset by swap termination

+ NTC (CA) – lower maintenance expense

- Sale of Delta-Person and Gregory

- Other projects in West – higher maintenance expense

- Selkirk – lower dispatch (mild summer); PPA expiration

- Outages at Cadillac, Calstock, Chambers; declines at

Curtis Palmer and Kenilworth

Project Adjusted EBITDA

2014 2013 Change

YTD September 221.6 211.4 10.2

Q3 2014 Q3 2013 Change

Cash flows from operating activities $40.4 $46.4 $(6.0)

APLP term loan facility repayments (9.6) - (9.6)

Project-level debt repayments (4.2) (1.7) (2.5)

Capex (7.5) (1.5) (6.0)

Distributions to noncontrolling interests (3.6) (1.4) (2.2)

Dividends on preferred shares (2.9) (3.2) 0.3

Free Cash Flow (Reported) $12.6 $38.6 $(26.0)

Cash Flow, Q3 2014 vs Q3 2013 ($ millions)

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Decrease due primarily to two factors:

• $(2.8) decrease in Project Adjusted EBITDA

• $(15.9) increased cash outflows for working

capital

Includes 1% mandatory amortization

and 50% cash sweep

Decrease due primarily to three factors:

• $(6.0) lower cash flows from operating

activities

• $(9.6) of term loan facility repayments by

APLP

• $(6.0) higher project capex, mostly at

Nipigon

Includes $6.1 at Nipigon for the steam

generator replacement and upgrade

Q3 Free Cash Flow was positive, in line with expectations and representing an improvement from 1H

YTD 2014 YTD 2013 Change

Cash flows from operating activities $45.9 $143.3 $(97.4)

APLP term loan facility repayments (47.1) - (47.1)

Project-level debt repayments (19.6) (12.2) (7.4)

Capex (10.0) (4.2) (5.8)

Distributions to noncontrolling interests (8.8) (4.4) (4.4)

Dividends on preferred shares (8.8) (9.5) 0.7

Free Cash Flow (Reported) $(48.4) $113.0 $(161.4)

Adjustments related to Q1 refinancing transactions:

Transaction-related interest expense 49.4 - 49.4

Piedmont construction debt repayment 8.1 - 8.1

Free Cash Flow (Adjusted) $9.1 $113.0 $(103.9)

See slide 44 for breakdown of refinancing and debt repurchase transaction-related costs.

Cash Flow, YTD September 2014 vs YTD September 2013 ($ millions)

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Decline due primarily to three factors:

• $(54) Transaction-related costs (Q1 2014)

- $(49) interest expense

- $(4) gas swap termination (Orlando)

• $(45) year-over-year changes in working capital

primarily due to:

- $36 decrease in prepaid and other assets

due to the collection of security deposits in

the first quarter of 2013

• $(33) cash flows from discontinued operations

(projects sold in 2013)

Partially offset by:

• $24 increase in distributions from

unconsolidated affiliates

• Other smaller positive factors

Includes $(8.1) for Piedmont debt paydown

at term conversion

Includes 1% mandatory amortization

and 50% cash sweep

Repaid $67 million of debt in the first nine months of 2014; on track for $85 million reduction this year

Organizational and Capital Structure

Information

100531 19

Atlantic Power Corporation

Atlantic Power Transmission & Atlantic Power Generation

Project Location Type

Economic

Interest

Net

MW

Contract

Expiry

Cadillac Michigan Biomass 100% 40 12/2028

Canadian Hills Oklahoma Wind 99% 295 12/2032

Chambers New Jersey Coal 40% 105 12/2024

Goshen North Idaho Wind 12.5% 16 11/2030

Idaho Wind Idaho Wind 27.56% 49 12/2030

Koma Kulshan Washington Hydro 49.8% 6 12/2037

Meadow Creek Idaho Wind 100% 120 12/2032

Orlando Florida Nat. Gas 50% 65 12/2023

Piedmont Georgia Biomass 100% 53 12/2032

Rockland Wind Idaho Wind 50% 40 12/2036

Selkirk New York Nat. Gas 18.5% 64 Merchant

Atlantic Power Limited Partnership

Project Location Type

Economic

Interest

Net

MW

Contract

Expiry

Calstock Ontario Biomass 100% 35 6/2020

Curtis Palmer New York Hydro 100% 60 12/2027

Frederickson Washington Nat. Gas 50% 125 8/2022

Kapuskasing Ontario Nat. Gas 100% 40 12/2017

Kenilworth New Jersey Nat. Gas 100% 30 9/2018

Mamquam B.C. Hydro 100% 50 9/2027

Manchief Colorado Nat. Gas 100% 300 10/2022

Morris Illinois Nat. Gas 100% 177 11/2023

Morseby Lake B.C. Hydro 100% 6 8/2022

Naval Station California Nat. Gas 100% 47 12/2019

Naval Training California Nat. Gas 100% 25 12/2019

Nipigon Ontario Nat. Gas 100% 40 12/2022

North Bay Ontario Nat. Gas 100% 40 12/2017

North Island California Nat. Gas 100% 42 12/2019

Oxnard California Nat. Gas 100% 49 5/2020

Tunis Ontario Nat. Gas 100% 43 12/2014

Williams Lake B.C Biomass 100% 66 3/2018

Organizational Structure

20

Capital Summary at September 30, 2014 ($ millions)

(1) Includes impact of interest rate swap

Note: C$ denominated debt was converted to US$ using US$ to C$ exchange rate of $1.12. 21

Atlantic Power Corporation

Maturity Amount Interest Rate

High-yield Notes 11/2018 $319.9 9.0%

Convertible Debentures (ATP.DB) 10/2014 $40.0 (C$44.8) 6.5%

Convertible Debentures (ATP.DB.A) 3/2017 $60.2 (C$67.4) 6.25%

Convertible Debentures (ATP.DB.B) 6/2017 $71.9 (C$80.5) 5.6%

Convertible Debentures (ATP.DB.U) 6/2019 $130 5.75%

Convertible Debentures (ATP.DB.D) 12/2019 $89.3 (C$100) 6.0%

Atlantic Power Limited Partnership

Revolving Credit Facility 2/2018 $0 3.75%

Term Loan 2/2021 $552.8 5.07% (1)

Medium-term Notes 6/2036 $187.5 (C$210) 5.95%

Preferred shares (AZP.PR.A) N/A $123 (C$125) 4.85%

Preferred shares (AZP.PR.B) N/A $98 (C$100) 7.0%

Atlantic Power Transmission & Atlantic Power Generation

Project-level Debt (consolidated) Various $378.3 Various

Project-level Debt (equity method) Various $112.3 Various

0

100

200

300

400

2014 2015 2016 2017 2018 2019 2020 2036

Bullet Debt Maturity Profile at September 30, 2014 ($ millions)

22

APLP Medium-term Notes APC Convertible Debentures APC High-yield Notes

$40

$132

$188

$219

Total

$899

million

(1) See slide 23 for Debt Amortization Schedule

(US$mm)

ATP.DB (repaid with cash October 31st)

$320

0

100

200

300

400

500

600

700

2014 2015 2016 2017 2018 Thereafter

Amortizing Debt Schedule at September 30, 2014 ($ millions)

23 See slide 22 for Bullet Debt Maturities Profile; (1) Includes Rockland consolidated at 100% ($84.4 million) , proportional interest in debt at the Company’s equity method projects of $112.0 million, and Piedmont bullet payment in 2018 of 51.5 million; (2) Projected 1% amortization (calculated on

declining balance of the APLP term loan) and 50% cash sweep on the APLP term loan assumes $6 million additional amortization in 2014, and projected annual amortization of $60 million/year in the remaining years with the assumption that the Company will repay approximately 70% of the

original $600 million term loan down by the end of its seven-year term.

• Project-level non-recourse debt totaling $491 million that amortizes over the life of the project PPAs

• $553 million 7-year amortizing term loan at APLP, which has 1% annual amortization (calculated on the declining balance of the loan) and a 50% sweep of APLP’s free cash flow

Total

$1,043

million

$14

$84 $82 $85

$645

$133

Projected 1% mandatory amortization and 50% cash sweep on APLP term loan (2) Project-level debt amortization (1)

(remaining)

Investment Summary

100531 24

Other 18%

Curtis Palmer 11%

Canadian Hills 9%

Meadow Creek 6%

Chambers 6%

Williams Lake 6%

Selkirk 5%

Manchief 5%

Nipigon 5%

Orlando 5%

Morris 4%

Naval Station 4%

Frederickson 4%

Rockland 4%

Tunis 3%

North Bay 3%

Cadillac 2%

Piedmont 2%

No single project contributed more than 11% to Project Adjusted

EBITDA for the nine months ended September 30, 2014 (1)

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Earnings and Cash Flow Well Diversified by Project East segment most significant contributor

(1) Based on $221.6 million in Project Adjusted EBITDA for the nine months ended September 30, 2014; does not include Project Adjusted EBITDA from discontinued operations. Unallocated corporate expenses are excluded from

project percentage allocation. Selected projects were projected to be top contributors and to comprise approximately 80% of the Company’s 2014 budget. (2) Based on $187.0 million in Cash Distributions from Projects for the nine

months ended September 30, 2014.

Note: Calculations include Delta-Person which was sold in July 2014.

YTD September 2014 Cash Distributions from

Projects by Segment (2)

YTD September 2014 Project Adjusted

EBITDA by Segment (1)

Capacity by Segment

East: 39%

West: 35%

Wind: 26%

(11 projects)

East 53%

West 28%

Wind 22%

East 48%

West 33%

Wind 19%

PPA Length (years) (1)

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Cash Flows Supported by Contracts with Creditworthy Offtakers AT’s portfolio has an average remaining PPA life of 10.0 years (1)

(1) Weighted by 2013 Project Adjusted EBITDA and excluding Gregory, Delta-Person and Greeley (the Company completed the sale of Gregory in August 2013, Greeley in March 2014, and Delta-Person in July 2014).

Pro Forma Offtaker Credit Rating (1)

A- to A+ 45%

AA- to AA 19%

AAA 7%

BBB- to BBB+ 23%

NR 5%

1 to 5 18%

6 to 10 32%

11 to 15 24%

15+ 26%

Investment Summary

27

• Portfolio of projects is well-diversified by fuel type, geography and customer

95% of the Company’s generating capacity is clean power (gas and renewables)

• Weighted-average remaining PPA term of approximately 10 years (1)

Approximately 80% of capacity is covered by PPAs that do not expire until 2020 and later

Proactively seeking to add PPAs beyond current expirations where economically attractive

• Targeting investments in existing projects with attractive return (20% current yield)

• Executing on cost reduction objectives and seeking additional savings

• Committed to delevering to our target credit metrics by year-end 2016

• Current dividend yield of 4.9%

$13 million annual level supported by currently anticipated Free Cash Flow generation

(1) As of September 30, 2014.

Appendix

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• Financial Results, Q3/YTD 2014 v. Q3/YTD 2013 29

• Segment Results, Q3/YTD September 2014 v. Q3/YTD September 2013 30

• Q3 2014 Operational Highlights 31

• YTD September 2014 Operational Highlights 32

• Project Adjusted EBITDA, Bridge of Q3 2013 to Q3 2014 33

• Project Adjusted EBITDA, Bridge of YTD September 2013 to YTD September 2014 34

• Other Q3 Developments 35

• Year-end 2014 Projected Debt Levels 36

• Capitalization as of September 30, 2014 37

• Liquidity as of September 30, 2014 38

• 2014 Guidance Detail 39-40

• Detail on G&A Expense 41

• Major Maintenance and Capex 42

• Q1 2014 Costs Associated with Refinancing and Debt Repurchase Transactions 43

• Calculation of APLP Cash Sweep 44

• Regulation G Disclosure 45

Financial Results, Q3/YTD 2014 vs Q3/YTD 2013 ($ millions)

29

Three months ended

September 30,

Nine months ended

September 30,

Unaudited 2014 2013 2014 2013

Excluding results from discontinued operations(1)

Project revenue $138.3 $140.0 $426.8 $413.4

Project income (loss) (68.6) 4.4 (52.2) 56.4

Project Adjusted EBITDA 72.2 75.0 221.6 211.4

Cash Distributions from Projects 51.2 65.7 187.0 169.7

Including results from discontinued operations (1)

Cash flows from operating activities $40.4 $46.4 $45.9 $143.3

Free Cash Flow (Reported) 12.6 38.6 (48.4) 113.0

Free Cash Flow (Adjusted) (2) 12.6 38.6 9.1 113.0 (1) The Path 15 transmission line (“Path 15”), Auburndale Power Partners, L.P. (“Auburndale”), Lake CoGen, Ltd. (“Lake”) and Pasco Cogen, Ltd. (“Pasco”) (collectively, the “Sold Projects”) were

sold in April 2013, the Company’s interest in Rollcast Energy (“Rollcast”) was sold in November 2013, and Thermo Power & Electric, LLC (“Greeley”) was sold in March 2014. Accordingly, the

revenues, project income (loss), Project Adjusted EBITDA and Cash Distributions from these assets are included in discontinued operations for the three and nine month periods ended September

30, 2013 and September 30, 2014. The results of discontinued operations are excluded from Project revenue, Project income, Project Adjusted EBITDA and Cash Distributions from Projects. Under

GAAP, the cash flows attributable to the Sold Projects, Rollcast and Greeley are included in cash flows from operating activities as shown on the Company’s Consolidated Statement of Cash Flows;

therefore, the Company’s calculation of Free Cash Flow also includes cash flows from the Sold Projects, Rollcast, and Greeley. The Gregory project, which was sold in August 2013, and the Delta-

Person generating station, which was sold in July 2014, are both accounted for under the equity method of accounting and therefore are included in the Company’s financial results from continuing

operations. (2) See slide 40 for calculation of Free Cash Flow (Adjusted) and its reconciliation to its comparable GAAP measure Cash flows from operating activities.

Note: Project Adjusted EBITDA, Free Cash Flow and Cash Distributions from Projects are not recognized measures under GAAP and do not have any standardized meaning prescribed by GAAP;

therefore, these measures may not be comparable to similar measures presented by other companies. Please refer to Slide 45 for reconciliations of these non-GAAP measures to GAAP measures.

30

Segment Results, Q3/YTD September 2014 vs Q3/YTD September 2013 ($ millions)

Three months ended

September 30,

Nine months ended

September 30,

2014 2013 2014 2013

Project income (loss)

East $(9.7) $(29.4) $17.7 $13.9

West (53.1) 41.8 (51.7) 42.5

Wind (3.5) (3.5) (11.1) 11.9

Un-allocated Corporate (2.3) (4.5) (7.1) (11.9)

Total (68.6) 4.4 (52.2) 56.4

Project Adjusted EBITDA

East $32.7 $33.5 $116.5 $112.1

West 28.3 32.7 62.3 67.3

Wind 14.1 12.9 49.0 43.4

Un-allocated Corporate (2.9) (4.1) (6.2) (11.4)

Total 72.2 75.0 221.6 211.4 Note: Project Adjusted EBITDA is not a recognized measure under GAAP and does not have any standardized meaning prescribed by GAAP; therefore, this measure may not be

comparable to similar measures presented by other companies. Please refer to Slide 45 for a reconciliation of this non-GAAP measure to a GAAP measure.

The Company has not reconciled non-GAAP financial measures relating to individual project segments to the directly comparable GAAP measure due to the difficulty in making the

relevant adjustments on a segment basis.

Q3 2013 Q3 2014 Q3 2013 Q3 2014 Q3 2013 Q3 2014 Q3 2013 Q3 2014

Q3 2014 Operational Performance: Improved Availability; Lower Dispatch

31

Generation across our portfolio decreased 8.5% for the quarter, driven by:

reduced dispatch at Manchief, Williams Lake and Selkirk, primarily due to

mild summer weather

scheduled maintenance at Chambers

+ increased generation in the Wind segment, primarily due to favorable winds

at Canadian Hills

Business recap:

• Wind – Wind generation up 9.0%, with Canadian Hills up 22% (vs Q3 2013)

• Hydro – Curtis Palmer and Mamquam generation reduced 10% and 5%,

respectively (vs Q3 2013)

• Thermal – Increased waste heat levels at Ontario projects (vs Q3 2013);

Kapuskasing and North Bay generation up 29% and 11%, respectively

Weighted Average Availability

Q3 2014 Q3 2013

East 94.0% 95.8%

West 96.3% 91.3%

Wind 97.3% 98.9%

Total 95.0% 94.8%

Aggregate Power Generation Q3 2014 vs. Q3 2013 (thousands, Net MWh)

East West Wind Total

1,008 928

2,023 2,211

373 343

722 860

(8.0)% (16.1)% 9.0%

(8.5)%

Availability factor of 95% vs. 94.8% in

Q3 2013 and improved vs. 92% in first

half 2014

+ Favorable outage comparisons vs

2013: Mamquam, Moresby Lake,

Koma Kulshan and Morris

Scheduled maintenance outage at

Nipigon

Most projects earned their expected

level of capacity payments during the

quarter (96% of total; impact of reduced

availability on capacity payments was

$1.8 million)

YTD Sept 2013 YTD Sept 2014 YTD Sept 2013 YTD Sept 2014 YTD Sept 2013 YTD Sept 2014 YTD Sept 2013 YTD Sept 2014

YTD September 2014 Operational Highlights

32

Generation increased 0.1%:

+ Piedmont added in April 2013 (additional quarter in 2014)

+ higher dispatch at Frederickson

+ improved wind conditions in Idaho (Meadow Creek)

- reduced dispatch at Manchief and Williams Lake

- reduced generation at Selkirk (mild summer weather)

- reduced generation at Tunis (scheduled turbine maintenance in 2014)

Business recap:

• Wind – Ahead of budget; generation from Idaho wind projects up 11% vs YTD Sept

2013, more than offsetting relatively flat results from Canadian Hills due to a

weather-related outage in Q1

• Hydro – Curtis Palmer generation up 4% YTD vs YTD Sept 2013; other hydro

projects also up for year

• Thermal – Below budget due to Q1 outages and $6.8 million capacity payment

shortfall, partially offset by higher Ontario waste heat levels

Weighted Average Availability

YTD

Sept 2014

YTD

Sept 2013

East 92.8% 95.2%

West 92.3% 90.8%

Wind 96.3% 98.6%

Total 93.0% 94.2%

Aggregate Power Generation YTD Sept 2014 vs. YTD Sept 2013 (thousands, Net MWh)

East West Wind Total

2,980 2,910

6,139 6,130

1,332 1,274 1,826 1,946

2.4% (6.1)%

4.5%

Extreme weather and several forced

outages, mostly in 1H, affected results

Ontario projects – unplanned

outages due to weather and other

factors in Q1

Piedmont – several forced outages

earlier this year, most recent in July

o Improved availability in

August (99.5%) and

September (98%)

Improved availability overall in Q3

YTD, reduced availability resulted in

capacity payments being $8.4 million

lower than their expected level (Ontario,

Piedmont, Cadillac and Morris); still

represented 94% of expected total

0.1%

Project Adjusted EBITDA Bridge of Q3 2013 to Q3 2014 – Significant factors ($ millions)

33

Q3 2013

$72.2 $75.0

Q3 2014

$(4)

West

Lower energy

revenues, higher

maintenance

expense (Navy

projects); lower

dispatch

(Manchief,

Williams Lake);

sale of Delta-

Person and

Gregory $(1.5)

$3

Ontario gas

projects

Favorable outage

comparisons and

higher waste

heat

(Kapuskasing,

Nipigon)

Scheduled

outages

Calstock

Chambers

$(2)

Other

Lower water

(Curtis Palmer);

other projects

$3

Orlando

Favorable

changes to PPA

and gas costs

$2

Canadian Hills

Favorable wind

$(3)

Selkirk

Lower dispatch

due to mild

summer weather;

PPA expiration

(8/14)

$(2)

Project Adjusted EBITDA ($ millions) Bridge of YTD September 2013 to YTD September 2014 – Significant factors

34

YTD

Sept

2013

$221.6

$211.4

YTD

Sept

2014

$5

Un-allocated

Corporate

Reduction in G&A

and development

expense

$8

Morris

Lower

maintenance

and fuel

expenses

(outage in

2013), higher

merchant

capacity and

ancillary

services

revenues

$(8)

All other East

Outages at

Cadillac,

Calstock,

Chambers;

declines at

Curtis Palmer

and Kenilworth

$6

Wind Projects

Favorable

winds

$5

Ontario gas

projects

Increased

waste heat,

decreased

maintenance

expense

$(4)

Selkirk

Lower dispatch

due to mild

summer weather;

PPA expiration

(8/14)

$(5)

West

Naval

Training

Center +$4

(lower

maintenance

expense);

sale of

Delta-Person

and Gregory

$(3); other

projects due

to

maintenance

and other

factors $(6)

$3

Orlando

Favorable

changes to

PPA and

gas costs,

offset by

gas swaps

termination

$(4)

Other Developments in Q3

35

• Completed event-driven goodwill impairment analysis in Q3

Full impairments of Kenilworth and Manchief; partial impairment of Williams Lake

Total impairment charge recorded in Q3 of $91.8 million ($106.6 million YTD)

Still required to conduct annual impairment assessment in Q4

• Piedmont is not in compliance with its debt service coverage ratio, which went in to effect

in February 2014 at term conversion

Expect no distributions from the project for at least the next 18 months

Previous expectation had been through mid-2015

• 9.0% senior unsecured notes fixed charge coverage ratio/restricted payments basket

update

$29.3 million of dividends declared through August 2014 dividend

Expect to be back in compliance in the first half of 2015, assuming no additional prepayment

charges recorded

Unaudited

APC APLP

Project-level

(consolidated)

Project-level

(equity

method) Total

December 31, 2013 $865 $612 $399 $119 $1,995

Issuance of APLP term loan 600 600

Redemption of Curtis Palmer (190) (190)

Redemption of USGP notes (225) (225)

Repurchase of high-yield notes (140) (140)

Amortization of APLP term loan (1% and 50% cash sweep) (47) (47)

Paydown of Piedmont debt (8) (8)

Other project debt amortization (12) (1) (13)

Sale of Delta-Person (6) (6)

F/X impact (14) (10) (24)

September 30, 2014 $711 $740 $379 $112 $1,942

Projected Year-End Adjustments:

Repayment of convertible debentures (ATP.DB) on October 31 (41) (41)

Amortization of APLP term loan (1% and 50% cash sweep) (6) (6)

Repayment of project-level debt (7) (1) (8)

Projected Year-End 2014 Debt (1) $670 $734 $372 $111 $1,887

Year-end 2014 Projected Debt Levels Expect to reduce total debt by approximately $85 million in 2014 (excluding F/X impacts)

36

• Amortization of APLP term loan reduces interest expense by another $3 million annually on average

• Reported interest expense to decline less because of amortization of deferred financing costs associated with the refinancing (~$5 million/year)

(1) Does not include possible purchases of the Company’s convertible debentures under the Normal Course Issuer Bid (“NCIB”) the Company expects to commence on November 11, 2014, and that will run through November 10, 2015 unless otherwise

terminated. Please see the Company’s news release dated November 6, 2014 for details concerning the NCIB.

Capitalization ($ millions) Presented on a consolidated basis and excludes equity method projects

37

June 30, 2014 September 30, 2014

Projected

December 31, 2014(1)

Long-term debt (incl. current portion)

APC revolving credit facility - - -

APC High-yield Notes $320 $320 $320

APLP Medium-Term Notes (2) 197 188 188

APLP revolving credit facility 0 0 0

APLP Term Loan 562 553 547

Project-level debt (non-recourse) 383 378 371

Convertible debentures (2) 408 391 350

Total long-term debt $1,870 72% $1,830 75% $1,776 74%

Preferred shares 221 8% 221 9% 221 10%

Common equity (3) 509 20% 390 16% 390 16%

Total shareholders equity 730 28% 611 25% 611 26%

Total capitalization $2,600 100% $2,441 100% $2,387 100%

(1) Accounts for: repayment on October 31st of $41 (Cdn$44.8) million convertible debentures (ATP.DB); 1% mandatory amortization and 50% cash sweep on APLP’s term loan (expected to be approximately $6

million in the fourth quarter of 2014); and project-level debt repayments of $6.6 million in the fourth quarter of 2014.

(2) Quarter-over-quarter change due to F/X impacts, except change from September 30 to December 31 projected, which accounts for $41 million repayment of October 2014 convertible debentures.

(3) Common equity includes other comprehensive income and retained deficit. Year-end projection does not reflect changes to retained deficit.

Liquidity ($ millions)

38

Unaudited June 30, 2014 September 30, 2014 Pro Forma

Revolver capacity $210.0 $210.0 $210

Letters of credit outstanding (107.0) (106.0) (106)

Unused borrowing capacity 103.0 104.0 104

Unrestricted cash (1) 157.6 167.6 127

Total Liquidity 260.6 $271.6 $231

(1) Includes project-level cash for working capital needs of $16.3 million at September 30, 2014 and $16.4 million at June 30, 2014. Pro forma unrestricted cash reflects repayment of $41 million (Cdn$44.8 million) of

convertible debentures (ATP.DB) on October 31, 2014 at maturity.

• Used $41 million of cash to repay Cdn$44.8 million convertible debentures at maturity in October 2014

• Planned cash reserve needed for the working capital needs of the business is approximately $80 to $100

million

Project Adjusted EBITDA Bridge of 2013 Actual to 2014 Guidance ($ millions)

39

Actual

$269

Piedmont

Full year of

operations,

partially offset

by outages,

fuel costs and

legal

expenses

Projects

Sold

Delta-Person

Gregory

$(4)

Guidance

$285 - $300

2013 2014

Orlando

Favorable

changes to

PPA and gas

contract, offset

by gas swap

termination

$(4)

$6

Morris

Higher

generation,

deferred

revenues,

lower O&M,

partially offset

by lower

capacity

revenues

$6

Lower

unallocated

corporate

expenses,

including

development

(non-G&A)

Other

projects

Lower

dispatch and

other factors

$(4)

Wind and Hydro

2013 below

normal;

Wind +$9

Hydro +$4

$2 $13

$10

Selkirk

Lower

merchant

prices for

2014;

Expiration

of PPA

(8/2014)

$(10)

Outages

Higher

maintenance

costs:

Cadillac

Calstock

Chambers

Naval Station

Williams Lake

$(5)

Changes since Q2 2014 presentation:

Morris $(1)

Piedmont $(1)

Selkirk $(1)

Outages $(1)

Wind and hydro $ 2

Other, net $ 2

Naval Training

Center

Favorable

maintenance

comparison

$4

Ontario

Gas projects

(higher waste

heat)

$5

2014 Guidance

2/27/14

2014 Guidance

11/6/14

YTD Sept

2014 Actual

Project Adjusted EBITDA $280 - $305 $285 - $300 $221.6

Adjustment for equity method projects (1) (11) (5) (10.0)

Corporate G&A expense (33) (35) (26.7)

Interest expense (2) (165) – (170) (170) (147.1)

Cash taxes and changes in working capital (10) (14) 8.1

Cash flows from operating activities (2) $60 – $85 $60 – $70 $45.9

Maintenance capex and optimization investments (capitalized portion) (3) (16) (16) (10.0)

Repayment of project-level debt (26) (26) (19.6)

APLP: 1% mandatory term loan amortization and estimate of 50% cash sweep (52) – (55) (53) (47.1)

Distributions to noncontrolling interests (4) and dividends on preferred shares (23) (23) (17.6)

Free Cash Flow (Reported) $(60) – $(35) $(58) – $(48) $(48.4)

Add back:

Make-whole payments, premiums and accrued interest expenses associated

with refinancing (2)

49 49 49.4

Principal payment of Piedmont construction debt at term loan conversion 8 8 8.1

Free Cash Flow (Guidance/Adjusted) $0 – $25 $0 – $10 $9.1

Footnotes: (1) Represents difference between Project Adjusted EBITDA and cash distributions from equity method projects; (2) See slide 40 for detail of transaction costs included herein; (3) Includes

optimization capex of $15 million; (4) Primarily tax equity investors (Canadian Hills) and minority interest (Rockland).

2014 Guidance ($ millions) Narrowing 2014 Project Adjusted EBITDA Range; Lowering Free Cash Flow Guidance

40

Sharpening Our Cost Focus

41

Corporate G&A and Development Expense ($ millions)

2014

Guidance

(11/6/14)

2013

Actual

Included in Project Adjusted EBITDA:

Development (1) $5 $7.2

Project G&A and other 4 11.4

Unallocated corporate 9 18.6

Excluded from Project Adjusted

EBITDA:

Administration expense (Corporate G&A) 35 35.2

Total $44 $53.8

Have already taken steps to achieve at least $15 million annual savings in 2015 relative to 2013

(1) Includes approximately $3 million annual contractual obligation related to Ridgeline acquisition that will terminate in the first quarter of 2015.

Includes:

- Operations & Asset Management

- Environmental, Health & Safety

- Ridgeline

- Project Accounting

Includes:

- Executive & Financial Management

- Treasury, Tax, Legal, HR, IT

- Corporate Accounting

- Office & administrative costs

- Public company costs

- One-time costs (mostly severance)

Includes ~$6 severance

charges not expected to recur

in 2015, most of which is in

corporate G&A line

Calculation of APLP Cash Sweep ($ millions)

42

2014 APLP Project Adjusted EBITDA ($165 - $175)

Less:

Capitalized portion of major maintenance and capex

= Cash flow before debt service

Less:

Interest expense on revolving credit facility

Interest expense on term loan

Interest expense on medium-term notes

Term loan 1% fixed mandatory amortization

= Cash flow before 50% cash sweep (1)

(1) The cash sweep and distributions to the Company from APLP occur at each quarter end.

50% retained at APLP

Less:

Preferred share dividends

= Distributions to APC (1)

50% applied to amortize

term loan at APLP

Unaudited 2014 Guidance

Total major maintenance and capex $35

Expensed (included in EBITDA) 20

Capitalized 16

Optimization investments ($[15] million of which is included above) $18

Major Maintenance and Capex ($ millions)

43

• On track to invest approximately $27 million in optimization initiatives in 2013 - 2014

- Expected run-rate cash flow contribution of at least $8 million annually in 2015, at least half of which has already

been realized in 2014

• Expected recurring major maintenance expense ~ $25 million/year

• In addition, targeting $5 to $10 million/year of ongoing optimization investments, on average

• 2015 major maintenance and capex expected to be approximately $30 to $35 million, including approximately $5 to $10

million of discretionary capex

Curtis Palmer Unit 5 repowering $2

Nipigon steam generator replacement and upgrade $8

North Island increased interconnection capacity $1

Morris investment to boost energy output $3

Morris water treatment upgrade $1

Other $3

Q1 2014 Costs Associated with Refinancing and Debt Repurchase Transactions

($ millions)

44

Make-whole payments and other premiums (US GPs, 9.0% senior unsecured notes) $(34)

Accrued interest (US GPs, Curtis Palmer, 9.0% senior unsecured notes) (12)

Termination of interest-rate swaps (EPP) (3)

Total included in interest expense $(49)

Termination of Orlando gas swaps (included in fuel expense) (4)

Total included in Operating and Free Cash Flow $(54)

Financing expenses and fees $(40)

Amendment to Piedmont interest-rate swap (1)

Total deferred financing costs (included in Financing Cash Flow) (1) $(41)

Total cash costs $(94)

Non-cash write-off of deferred financing costs (included in interest expense) (6)

Total all costs $(100)

(1) Amortized over the life of the financing.

Amount excluded from 2014 Free Cash Flow guidance

Regulation G Disclosures

Project Adjusted EBITDA, Cash Distributions from Projects and Free Cash Flow are not measures recognized under GAAP and do not have standardized meanings prescribed by GAAP. Management believes that Free Cash Flow and Cash Distributions from

Projects are relevant supplemental measures of the Company's ability to earn and distribute cash returns to investors. Reconciliations of Free Cash Flow to cash flows from operating activities and of Cash Distributions from Projects to Project income (loss) are

provided below. Investors are cautioned that the Company may calculate these measures in a manner that is different from other companies.

Free Cash Flow is defined as cash flows from operating activities less capex; project-level debt repayments, including amortization of the new term loan; and distributions to non-controlling interests, including preferred share dividends.

Project Adjusted EBITDA is defined as project income (loss) plus interest, taxes, depreciation and amortization (including non-cash impairment charges) and changes in fair value of derivative instruments. Project Adjusted EBITDA is not a measure recognized

under GAAP and is therefore unlikely to be comparable to similar measures presented by other companies and does not have a standardized meaning prescribed by GAAP. Management uses Project Adjusted EBITDA at the project level to provide comparative

information about project performance and believes such information is helpful to investors. A reconciliation of Project Adjusted EBITDA to project income (loss) and a bridge to Cash Distributions from Projects are provided below. Investors are cautioned that

the Company may calculate this measure in a manner that is different from other companies.

45

(Unaudited) Three months ended September 30, Nine months ended September 30,

2014 2013 2014 2013

Cash Distributions from Projects $51.2 $65.7 $187.0 $169.7

Repayment of long-term debt (4.5) (5.6) (22.5) (22.5)

Interest expense, net (7.5) (10.6) (26.2) (30.4)

Capital expenditures (7.4) (2.1) (10.4) (8.6)

Other, including changes in working capital (1.6) 9.0 24.5 19.8

Project Adjusted EBITDA $72.2 $75.0 $221.6 $211.4

Depreciation and amortization 50.4 51.1 154.8 153.5

Interest expense, net 7.6 10.7 32.4 30.5

Change in the fair value of derivative instruments (0.4) 3.6 (11.5) (34.8)

Other (income) expense 83.2 5.2 98.1 5.8

Project (loss) income $(68.6) $4.4 $(52.2) $56.4

Administrative and other expenses (income) 16.9 45.0 125.0 84.8

Income tax (benefit) expense 5.6 - (7.4) (1.9)

Net loss from discontinued operations, net of tax - - (0.1) (5.2)

Net (loss) income $(91.1) $(40.6) $(169.9) $(31.7)

Adjustments to reconcile to net cash provided by operating activities 118.9 57.2 209.6 123.7

Change in other operating balances 14.1 29.8 6.2 51.3

Cash flows from operating activities $40.4 $46.4 $45.9 $143.3

Term loan facility repayments (1) (9.6) - (47.1) -

Project-level debt repayments (4.2) (1.7) (19.6) (12.2)

Purchases of property, plant and equipment (2) (7.5) (1.5) (10.0) (4.2)

Distributions to noncontrolling interests (3) (3.6) (1.4) (8.8) (4.4)

Dividends on preferred shares of a subsidiary company (2.9) (3.2) (8.8) (9.5)

Free Cash Flow $12.6 $38.6 $(48.4) $113.0 (1) Includes mandatory 1% annual amortization and 50% excess cash flow repayments by the Partnership. (2) Excludes construction costs related to our Canadian Hills project in 2014 and 2013 and our Piedmont and Meadow Creek projects in 2013. (3) Distributions to noncontrolling interests primarily include distributions, if any, to the tax equity investors at Canadian Hills and to the other 50% owner of Rockland.

Note: Cash Distributions from Projects, Project Adjusted EBITDA and Free Cash Flow are not recognized measures under GAAP and do not have any standardized meanings prescribed by GAAP; therefore, these measures may not be comparable to

similar measures presented by other companies.